ExxonMobil is a major player in the Alaska oil industry. But unlike peers BP Exploration (Alaska) Inc. and ConocoPhillips Alaska Inc., the global giant currently operates very little production in Alaska. In fact, Exxon only operates two Alaska fields: the as-yet-nonproducing Point Thomson unit on the eastern North Slope and, through subsidiary XTO Energy Inc., the Middle Ground Shoal field in Cook Inlet.
The fields are distinctly opposite.
Point Thomson is among the largest known yet undeveloped fields in Alaska. It is also strategically important because it would provide supplies for the proposed Alaska LNG project - of which Exxon is a sponsor - and because it would extend North Slope development infrastructure farther to the east, improving the economics of other fields.
By contrast, the small Middle Ground Shoal oil field and its two offshore platforms - called, simply, A and C - are among the oldest and hardiest assets in Cook Inlet.
Point Thomson
Exxon discovered the gas and condensate Point Thomson field in the 1970s but delayed development for decades because of technical, economic, legal and regulatory challenges.
After an initial delineation campaign, Exxon refrained from development work for years, which eventually tried the patience of state officials. A complex dispute ensued. The state and the company debated whether it was economically and technically wiser to prioritize condensate or gas production at the field, a decision that impacted project timelines.
The state initiated termination proceedings in 2008 to take back the leases, saying Exxon had fallen short of its responsibilities as a leaseholder. As a subsequent legal battle played out, the state gave Exxon permission to drill two wells at the unit: PTU-15 and PTU-16.
The parties reached a court-ordered settlement in early 2012 that created a timetable for Exxon to bring Point Thomson online by early 2016 and expand development thereafter.
Currently, Exxon is working on the first part of the deal: the Initial Production System.
Under a plan of operations filed after the settlement, Exxon proposed drilling a disposal well and up to five producers or injectors - a total which includes the two wells completed in recent years - from west, central and east pads. The three gravel pads would allow Exxon to reach all sections of the reservoir with extended-reach drilling.
The two recent wells are on the central pad. Exxon proposed drilling one well each on the west and east pad, and said it would site the fifth well based on the results of the previous four.
In 2013, Exxon claimed several “infrastructure milestones.”
By September 2013, the company had finished building an airstrip, a service pier and a permanent camp with operational telecommunications and power systems at Point Thomson. The company opened a new gravel mine and installed some 2,200 vertical support members for an above ground pipeline connecting the field to existing North Slope infrastructure. The 2013 program also saw Hyundai Heavy Industries begin construction work on the Point Thomson production modules at its facilities in Korea.
By June 2014, ExxonMobil had finished building a 70,000 bpd pipeline along 22 miles of Beaufort Sea coastline to the existing Badami pipeline, where liquids will flow to the trans-Alaska oil pipeline. ExxonMobil pegged the cost of the pipeline at $250 million.
The pipeline is bigger than what Exxon will need for its initial Point Thomson plans. The excess capacity is meant to accommodate future developments to the east, including the Red Dog, Telemark, Kuvlum-Lonestar, Stinson and Yukon Gold prospects and any potential development from the currently restricted Arctic National Wildlife Refuge.
In July, the Alaska Department of Environmental Conservation preliminarily approved an “air quality control construction permit,” a necessity for any development at the field.
Those activities have paved the way for bigger work: barging the production modules to the field mid-2015, installing the modules, directionally drilling a production well and two injection wells and bringing Point Thomson into regular production by early 2016.
Future development
The Initial Production System aims to produce some 10,000 barrels per day of liquid condensate and cycle some 200 million cubic feet per day of residual gas into the field.
That scheme would neither recover the $4 billion Exxon expects to spend on the project by 2016 nor come close to fulfilling the full promise of the Point Thomson field. The estimated 8 trillion cubic feet of gas at Point Thomson constitutes some 25 percent of known North Slope reserves, making the field crucial for the success of future gas sales.
That’s why the 2012 settlement also included three future development options.
Under Alternative A, Exxon would sanction a “major” gas sale by June 2016. The sale would have to be at least 500 million cubic feet per day, which would require a large diameter pipeline from the North Slope, a project Alaskans have wanted for decades.
The current project consists of a large diameter gas pipeline connecting Prudhoe Bay facilities to a new liquefied natural gas export facility in Nikiski, on the Kenai Peninsula.
Over the course of 2014, the producers BP, ConocoPhillips and Exxon, the pipeline builder TransCanada and the state of Alaska created a framework for moving ahead on preliminary engineering and for establishing a commercial terms for that project. The Point Thomson settlement helped those efforts, Gov. Sean Parnell told Petroleum News in July 2014. “We were making what I call commensurate proportionate commitments,” he said. “Meaning, you take a step. We take a step. You take a step. We take a step.”
While those agreements represent the most progress on the project in years - and some would say the most progress ever - a major question persists: cost. In 2012, the three producers and TransCanada estimated the project would cost between $45 billion and more than $65 billion, figures which are unlikely to go anywhere but up over time.
Under Alternative B, the Point Thomson producers would commit to expand liquids production to 30,000 bpd or more by 2019. The alternative is only possible if the Initial Production System proves the feasibility of gas cycling at Point Thomson. The program would require Exxon to drill more wells and expand processing capacity at the field.
Under Alternative C, the producers would integrate Point Thomson and Prudhoe Bay to improve recovery at both fields. The scheme involves injecting Point Thomson gas into Prudhoe Bay to enhance oil recovery at the aging field, expanding Point Thomson liquids production and dedicating a significant volume of gas for in-state use no later than 2019.
The settlement also requires Exxon to develop a Brookian oil reservoir by 2018.
Middle Ground Shoal
The Point Thomson project is large enough to guide public policy. By contrast, the XTO-operated Middle Ground Shoal field is much more modest.
Shell Oil discovered the field in 1963 with MGS State No. 1, the first offshore oil completion in Alaska, according to the American Association of Petroleum Geologists.
By the time XTO-predecessor Cross Timbers Oil Co. purchased Middle Ground Shoal from Shell in 1998, the offshore field was producing 3,600 barrels per day and falling. By 2006, XTO had drilled 12 penetrations throughout the field, which doubled oil reserves to 24 million barrels and brought oil production into the range of 3,000 to 4,500 bpd.
That pace slowed as XTO turned its attention to more profitable assets. Despite ongoing maintenance, and various proposals over the years for additional development opportunities including sidetracks and wells into other formations, XTO hasn’t drilled at the field since 2005, according to Alaska Oil and Gas Conservation Commission records.
Still, Middle Ground Shoal remains important to the regional economy. The field accounts for approximately one-eighth of total Cook Inlet oil production, which has made XTO among the largest taxpayers in the Kenai Peninsula Borough for many years.
Even so, though, Middle Ground Shoal was probably irrelevant to Exxon in late 2009, when it purchased XTO in an all-stock deal worth $31 billion. Instead, Exxon wanted XTO’s sizable North American natural gas holdings as an entree to the unconventional boom.
